questions and answers

CUSTOMER BASED GENERATION EPA WORKSHOP QUESTIONS AND ANSWERS NOVEMBER 4, 2002 Refer to the Standard EPA for a complete understanding of the EPA terms and conditions. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 1 TABLE OF CONTENTS TOPIC PAGE LIQUIDATED DAMAGES ................................................................................................................................................................ 3 SUSPENSION & TERMINATION.................................................................................................................................................... 5 SECURITY.......................................................................................................................................................................................... 5 ECONOMIC HARDSHIP .................................................................................................................................................................. 5 FORCE MAJEURE ............................................................................................................................................................................ 7 BCUC................................................................................................................................................................................................... 7 STEAM ................................................................................................................................................................................................ 8 TRANSMISSION & METERING ..................................................................................................................................................... 9 STANDARD CONTRACT ............................................................................................................................................................... 11 COD ................................................................................................................................................................................................... 11 DISCRETION ................................................................................................................................................................................... 13 OPERATION .................................................................................................................................................................................... 13 CAPACITY / ELIGIBLE ELECTRICITY ..................................................................................................................................... 14 EXCESS GENERATION ................................................................................................................................................................. 15 PRICING & FLOW THROUGHS................................................................................................................................................... 16 GREEN & GHGS.............................................................................................................................................................................. 16 CPI ..................................................................................................................................................................................................... 18 HYDROLOGY ADJUSTMENT ...................................................................................................................................................... 19 PROCESS .......................................................................................................................................................................................... 19 CODE OF CONDUCT...................................................................................................................................................................... 20 BCIAC (arbitration) PROCESS....................................................................................................................................................... 20 PUBLIC ANNOUNCEMENTS ........................................................................................................................................................ 20 1. PLEASE NOTE – SOME OF THE QUESTIONS AND COMMENTS HAVE RESULTED IN CHANGES TO THE EPA. PLEASE REFER TO THE CBG-EPA CHANGE SUMMARY DOCUMENT WHICH WILL FORM THE BASIS FOR A REVISED EPA. ANSWERS TO THE REMAINING QUESTIONS PROVIDED BELOW ARE INTENDED TO PROVIDE FURTHER CLARIFICATION. 2. PLEASE ALSO NOTE THE QUESTIONS AND ANSWERS HAVE BEEN CONSOLIDATED AND EDITED FOR CLARITY. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 2 Liquidated Damages Q & A QUESTION 1. ANSWER You have said that any monthly LD’s paid will be Per Appendix 4, Section 3 at page 3, in calculating the Annual Capacity Factor deducted from any annual LD’s that might become LD’s, the Monthly Capacity Factor LDs (“PMLDs”) previously paid by the Seller payable. Where is this provided for in the EPA? are deducted. [Cross reference also to the release relating to the changes made to the CFT and EPA] The Monthly Capacity Factor LDs are based on deliveries of less than 90 percent of Monthly Contracted Electricity. Is it possible for the Seller to produce below 90 percent at times during the month and not be subject to Monthly Capacity Factor LDs? It is possible that production at times during the month could be below 90 percent of the Contracted Capacity per Attachment C of the Call for Tenders without incurring Monthly Capacity Factor LDs. However, Eligible Electricity at any time during the month can not exceed 110 percent of Contracted Capacity. This restricts the Seller’s ability to “make up” for production shortfalls. 2. 3. Why are you using the MID-C price as the reference The MID-C price is the reference because it is the nearest transparent and liquid for damages? hub for electricity. Is it possible to “firm up” energy by buying storage No. from BC Hydro? The 22 projects have dwindled down to 16 and presumably the 3300 GWh has dropped off as well. Has BC Hydro considered what options they may have if they are unsuccessful in fulfilling the 800 GWh? We look at possible sources of energy, firm and non-firm, and evaluate the probability of achieving them. We will continue to evaluate energy sources and we plan a series of calls that would be more significant than this call alone. There is a risk that we may not get the 800 GWh. There is also a risk that we get signed documents and the energy doesn’t appear. 4. 5. 6. With respect to cash flow, would a payment See Section 8 of the EPA. Any monthly LD's would normally be included in the necessarily have to occur? When are LD's payable? Seller’s invoice and therefore be set-off against amount payable by BC Hydro for energy delivered. If the LD’s payable are greater than the amount payable by BC Hydro for energy delivered, the Seller’s invoice will show that the Seller owes BC Hydro and the Seller’s payment to BC Hydro is due within 15 days. If BC Hydro is looking for firm energy, would BC The program anticipates that there is firm energy available at less than the ceiling Page 3 7. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Hydro consider oversubscribing and widening the band on firmness to, minus 30 to plus 10, and then look at lowering your ceiling price? 8. Changes in law and energy prices can be absorbed through the utility rate structure. The Economic Hardship provision provides only partial relief. Fuel price risk should be assumed by BC Hydro in the same way that it assumes that risk in its own plants. Why are these changes/risks borne by the Seller in this agreement? price and we have some discretion in terms of raising the target of 800 GWh. However, we are not including less firm supply at lower prices in this program. The ceiling price for the program reflects the all-in price of supply including fuel price risk, based on a fixed price structure not a tolling or flow-through structure. We will not be changing the pricing structure for this call so Bidders must evaluate their risk and bid accordingly. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 4 Suspension & Termination Q & A 9 QUESTION The fact that BC Hydro can terminate for the failure to have interconnection/facilities agreements in place before the end of the initial period places unnecessary risk on the Seller, particularly since the delivery of these agreements are largely within BC Hydro’s control: Why not change this requirement? The Seller has more at risk than the Buyer under these contracts. Why do you not have a termination provision where the Buyer makes a termination payment to the Seller if the Seller terminates? ANSWER The condition can be waived by the IPP at any time prior to expiry of the initial period. In addition the initial period may be extended by 90 days if required. 10 This provision is included in Section 15.4 of the EPA, which specifically states that the Buyer shall pay the Termination Payment to the Seller if the Seller terminates the EPA under subsection 15.2 (b), a Buyer Default. Security Q & A QUESTION 11 ANSWER Is there an opportunity to offer a guarantee instead of The tender security must be in the form of cash or Letter of Credit. However, in cash or a letter of credit for the required securities? the case of the operating security, there is an opportunity per section 13.6 to offer a guarantee. Economic Hardship Q & A 12 QUESTION The long-term Sumas natural gas price of USD$3.01 per MMBtu identified on the website (http://www.bchydro.com/customergen) is lower than longterm market quotes received from counterparties. If this is the case, how will Sellers meet the $55 ceiling price? ANSWER The USD$3/MMBTU natural gas price is the levelized value of BC Hydro's longterm forecast of natural gas prices at Sumas. The forecast is based on a composite of market forwards and industry expert forecasts over the short, medium and long term. The forecast essentially reflects the mid-range of industry expert forecasts, so it is not surprising that counterparty quotes may be higher than USD$3/MMBTU. On the other hand, others are forecasting long-term gas prices Page 5 Customer Based Generation – November 4, 2002 Workshop Questions & Answers that are lower than USD$3/MMBTU, for example the 2002 Annual Energy Outlook Low Economic Growth Case shown on the website. Quotes received from counterparties may be higher for various reasons including lack of liquidity for 10 and 15-year terms, current events in the market and relatively wide bid-offer spreads. It will likely be the case that given differing plant configurations, fuel types, and plant efficiencies, some projects will be able to meet the Ceiling Price whereas some projects cannot. 13 The economic hardship provision only applies if the hardship is sustained for more than 90 days and does not extend beyond 730 days because of BC Hydro’s right to terminate. Ninety days is too long to have a severe economic hardship imposed on the Seller before being able to seek relief. Can this time frame be reduced? How did BC Hydro arrive at 730 days for cumulative Hardship Hours before termination? Why not 3 years? The hardship clause was not intended to deal with short term impacts, but rather to provide relief from Liquidated Damages in situations beyond the Seller’s control that threaten the long-term economic viability of the Seller’s Plant. With this in mind we will not be changing the 90-day time frame. 14 BC Hydro considered making this provision parallel the provision for termination in the event of prolonged force majeure, i.e. after the condition had pertained for the equivalent of 365 days. However, since Hardship Events are likely to be of a less sudden nature, both as to their inception and termination, it was felt that a longer period was warranted – and 730 days was chosen. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 6 Force Majeure Q & A 15 QUESTION Why are the Force Majeure provisions so restrictive in using natural or other causes such as changes in forest tenure, natural gas shortages due to unforeseen allocations under NAFTA or droughts affecting small hydro projects? ANSWER Firstly, this is a fairly standard definition of force majeure. As well, natural events or causes can be events of force majeure under the definition in Appendix 1 (ee). It is difficult to see how a change in forest tenure, by itself, could constitute force majeure, but if e.g. the government decided to expropriate a particular forest tenure or change the laws relating to them to such an extent that it was not possible to obtain required fibre from them, this potentially could qualify as force majeure under item (iv) of the definition. Changes of this type would most likely fall under the Hardship Event provisions, however, and would be excluded from force majeure by the exclusionary wording at the commencement of the definition. Similarly, actions taken under NAFTA could potentially be a force majeure event or a Hardship Event, depending on their nature and effect. Finally, in the case of a hydro project, in the situation mentioned, if the bidder had elected to be subject to the hydrology adjustment, this would provide the relief sought if non-delivery was due to hydrology limitations. 16 The 365-day limit on Force Majeure could be very tight. Significant reconstruction often takes longer than that Could the Seller have a mechanism for extending Force Majeure if the Seller is acting diligently to cure? In the case of “major damage” to the Seller’s Plant, if the Seller invoked force majeure in accordance with the EPA, section 9.3 of the EPA would govern, effectively extending the rebuild period to 730 days before the right of termination could be exercised. BCUC Q & A 17 QUESTION I just had a question about your definition of public utility, I’m from the Fraser Valley Regional District and I’m not sure if that fits the definition of a public utility and where things may go with water and the sale ANSWER Condition Subsequent 3.1(c) relates to exemption as a “public utility” in respect of the supply or sale of electricity. Bidders should consult the Utilities Commission Act (“UCA”) and obtain professional legal advice relating to any issues under the UCA. Page 7 Customer Based Generation – November 4, 2002 Workshop Questions & Answers of water and stuff? 18 What if the Buyer is deregulated and is no longer a public utility? How would that be handled in the EPA? Under section 16 .1(b) of the EPA, either party may assign its interest in the EPA to an Affiliate without the consent of the other party. However, the assignor, and any guarantor, remain liable under the EPA, and the assignee (other than a lender) must agree to assume all the obligations of the assignor under the EPA. Any other assignment or restructuring of the EPA requires the consent of both parties. The intent under this call is to purchase firm energy. Increasing the flexibility reduces the “firmness” of the energy. For this call, BC Hydro will maintain this requirement. Also, flexibility is provided by the ability to nominate a different Contract Capacity for each year of the contract as well as the project’s monthly profile. The definition of a public utility is in the Utilities Commission Act (UCA). A copy can be obtained from the BCUC website (www.bcuc.com). IPPs selling power to BC Hydro are exempt from regulation by virtue of Ministerial Exemption M-22-0205. It is common in commercial agreements, where actions by an external agency could significantly alter the obligations of a party, or the benefits a party expects to derive under the agreement, to provide for a right of termination in those circumstances. The right provided in section 3.4 of the EPA is mutual to both parties. 19 The plus or minus 10% seems quite restrictive. Is there any room to move on this limitation? 20 How does one unfortunately become a regulated utility? 21 Why should the Seller get stuck with the development costs just because BC Hydro doesn’t like a decision of the BCUC (Subsection 3.4)? Steam Q & A QUESTION 22 Why does BC Hydro care about steam metering and why does the Seller have to pay for that metering? ANSWER BC Hydro desires to purchase firm electricity. The steam must be metered to maintain the intent of the EPA that Sellers cannot increase steam sales at the expense of electricity deliveries. The metering is part of the project cost, so the Seller must make allowance for it. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 8 Transmission & Metering Q & A 23 QUESTION Will the interconnection agreement include damages payable to the Seller, if indeed there is no transmission capacity available? ANSWER The Interconnection Agreement (IA) is an agreement stipulating the terms and conditions under which a generator is permitted to be electrically connected to the BC Hydro system. It does not give the Applicant the right to inject power in the BC Transmission System. Therefore, the IA does not include any provisions for payment if no transmission capacity is available. The rights to inject and move power on the transmission system (“wheeling”) are conveyed by the Wholesale Transmission Service (WTS) agreements. BCH as purchaser, is undertaking responsibility to arrange suitable wheeling “capacity”. Events such as line outages are considered Force Majeure events 24 We currently have a metering arrangement with BC Hydro where we both can query our substations and we’d like to continue that at this generator installation. Any problem with that? If you have metering that meets Industry Canada Weights and Measures, would that not be adequate? We expect to maintain this arrangement going forward. 25 Section 7.11 of the EPA indicates that the Electricity and Gas Inspection Act governs the metering equipment to be installed under this contract. However, there is a requirement [Section 7.11 (a)]that both the equipment and the location of the installation must be approved by the Buyer. We are members, of the Western Electricity Co-ordinating Council, WECC, the renamed 'WSCC'. We comply with those standards and they are reflected in our interconnection requirements in the IA. 26 On the preliminary interconnection study I understand BC Hydro wants to protect their network and system. I haven’t heard any reference to Western Systems Coordination Council technical interconnection requirements. Is this the standard of interconnection being applied to this program? You mentioned that the largest variable in the interconnection cost is due to protection requirements not correlated to generation size. Are there some general rules of thumb? Is it remoteness at the end of a long line? What are the good places and what are the 27 As a general rule of thumb, remote projects probably will have a higher cost but not necessarily. When a line is near capacity, we can’t accommodate very much more electricity and it can be expensive to find a suitable remedy. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 9 bad places? 28 Where’s the point of connection for the meter? Is it at the generator terminals? The physical location of the meter can be just about anywhere because the meters can be compensated to adjust for the distance between the physical meter location and the actual point of delivery. However, the EPA calls for the meter to be as close as practical to the generator terminals There is no cash payment. The credit shows up as in the location adjustment for the project, which BC Hydro will provide on December 17. 29 You mentioned that in several cases there may a connection that is in fact beneficial to the BC Hydro system, where there in fact may well be a credit. But does that credit result in a cash payment or just an adjustment to the bid evaluation? You mentioned there’s sixteen projects who’ve put their applications in. What’s the consequence of that in view that there were thirty-seven projects prequalified? Will you be identifying the remaining sixteen? Is there any chance you’ll have the interconnection studies done before December 17th? For my particular situation I have to get my numbers together to submit for financing prior to December 17, so it’s important for me to be able to go back and look at an ROI and have a pretty close idea of where I’m going to be. So, can you put on the Web site some examples in the next couple of weeks to give us a rough idea and see where we align with those examples? I believe that the losses on the Hydro system are around 7%, I believe, maybe 6%, so projects in the Lower Mainland or Vancouver Island I would think would reduce that, or eliminate those 6% losses. Is there any benefit to the projects in the Lower Mainland 30 There were thirty-seven that started and twenty-two made the short list and from the twenty-two, sixteen are still in the CFT process. 31 32 33 BC Hydro has no plans to reveal the identity or capacities of the remaining sixteen participants or the six who have chosen not to proceed. It is possible but unlikely. In one case, a small project of about 2 MW impacted on protection schemes in several substations. In other cases locations adding 20 or 30 MW of new generation may be little or no impact. As a result of this wide spectrum, it is not possible to come up with examples that will generally apply to IPP generation projects. The impacts are very project specific, and can only be quantified as a result of the preliminary interconnection study unique to that project. Provided you have submitted your application on or before the submission deadline, your project specific interconnection costs will be provided to you on December 17, subject to the 130% cap. Line loss impacts are factored into the bid price evaluation through the Bulk Location and Area Location adjustments mentioned in the CFT documentation. The Bulk Location Adjustment adjusts for both capital and line loss impacts on BCH’s bulk transmission system. The Area Location Adjustment adjusts for any line loss impacts on BCH’s area transmission system. Note that the line loss Page 10 34 Customer Based Generation – November 4, 2002 Workshop Questions & Answers and Vancouver Island from a system loss point of view. impacts in the Area Location Adjustment are project specific, and are determined as part of the Generator Interconnection Preliminary Study. 35 Under Article 7.8(b)(iii) the obligations of the Buyer are subject to disconnection of the Seller’s Plant from the Transmission Authority’s system. What happens if the Seller is improperly disconnected? Why should the meter, transformers and related equipment be installed at the Seller’s cost? If a disconnection occurs and there is a dispute regarding whether or not it was proper, the issue would be dealt with by the dispute resolution mechanisms in the EPA and the Interconnection Agreement. 36 These items are for the sole purpose of facilitating the delivery of electricity from the Seller's plant and are therefore a project cost. Standard Contract Q & A 37 QUESTION What is the process to clarify the contract? ANSWER The process is to go through the Customer Generation website (www.bchydro.com/icustomergen) and submit the questions there by clicking on “Email Customer Generation.” We considered a number of contracts, involving parties such as Hydro Quebec, Nevada Power, Northern States Power, Western Systems Power Pool, and Edison Electric Institute. 38 What utility industry/IPP contracts were used as a basis for the Customer-Based Generation contract? COD Q & A 39 QUESTION As defined Plant Capacity is peak potential output and may not be achievable because of ambient conditions so it may not be possible to achieve COD for reasons beyond the control of the Seller (Subsection 5.2(a)). Can this clause be reworded to alleviate this problem? Why isn’t the Seller given the opportunity to cure any material default during COD (Section 5.2(b))? ANSWER The Plant Capacity, as set out in Appendix 5, will be derived from the information included in the Seller's Tender Form. The Seller therefore has the opportunity, guided by its engineering and supplier advisors, to specify a Plant Capacity that is achievable in accordance with this provision. Section 5.2 (b) of the EPA prevents COD from occurring if the Seller is in material default of the EPA, any permit, the Interconnection Agreement or the Facilities Agreement. If material defaults occur, and are continuing under any of Page 11 40 Customer Based Generation – November 4, 2002 Workshop Questions & Answers the agreements, permits, etc. as specified in 5.2(b), there is a very real risk that these agreements, permits, etc. could be suspended or terminated, thereby placing the whole foundation of the “deal” in jeopardy. The fact that COD cannot occur while material defaults of this nature are outstanding gives the Seller every incentive to proceed with all due diligence in the development of the project, and its efforts to cure any defaults. The consequence to the Seller is that it gets preCOD payments for a limited period and it doesn’t get paid post-COD electricity prices until COD is achieved. 41 In Section 5.2 it states that the Seller must have all permits required to operate the Seller’s Plant before COD is declared. Why isn’t the requirement only for material permits to operate the Seller’s Plant? The $20/MW.h for Pre-COD electricity for the 72 continuous hour COD trial period may not even cover the fuel cost. What is worse for other periods pre-COD BC Hydro does not pay anything. Why doesn’t BC Hydro pay more? The phrase ‘the later of (i) the commencement of the hour immediately following the hour in which the Seller’s Plant has complied with subsection 5.2(a) and (ii) 12:00 p.m. on the day 15 days prior to the date of delivery of the COD Certificate.” This is difficult to understand. Please explain. Does it include 5.2(c) (i)(iv)? If a permit is “required” for the operation of the Seller’s Plant, then the Plant cannot legally operate without it, and it is therefore a “material” permit. 42 This electricity has little value to BC Hydro because it is not known when it will be delivered or for how long. The Seller has the option of making arrangements to sell this electricity to others such as Powerex on a spot basis. 43 COD occurs on the later of 1. the beginning of the hour after the 72 hours of continuous operation has occurred at not less than Plant Capacity and 2. 12:00 PM 15 days prior to delivery of the COD certificate The first item is clear; the second item put the onus on the Seller to deliver the COD Certificate to BC Hydro. The COD Certificate certifies that all of the requirements of Section 5.2 have been met. The Seller has 15 days after completion of item (1) in which to deliver the COD Certificate without being penalised. For payment pre-COD, see Appendix 3, Part II of the EPA. For example, if the Seller takes 20 days to complete the requirements of Section 5.2 and deliver the COD Certificate, the Seller will achieve COD under (2) and will be paid the preCOD price for only the 72 hours prior to COD; the Seller will receive no payments for electricity delivered prior to the 72 hour pre-COD period. 44 Appendix 10 does not properly recognize the issues Appendix 10 was not designed to address permitting delays beyond those Page 12 Customer Based Generation – November 4, 2002 Workshop Questions & Answers associated with the development of small hydro projects and particularly the delays in permitting. Why not provide more flexibility related to development of these projects? contemplated in the main body of the EPA. The EPA allows for a 90-day extension to the initial period for such circumstances. Discretion Q & A 45 QUESTION Why does BC Hydro insist on unfettered discretion in providing consent approval or waiver (subsection 1.11(d))? Why not a reasonableness standard instead? ANSWER This is a typical stipulation in commercial agreements, and is applicable to both parties. Where it is intended that e.g. a party must act reasonably, or that other conditions will apply, this is specifically stated in the applicable provision. Operation Q & A 46 QUESTION What does “good operating practice” really mean and why does BC Hydro care? Under Section 6.5, BC Hydro gets to decide how the Seller operates its plant? What happens if electricity production is tied to industrial production and there is a winter shutdown for vacation or because of an oversupply of pulp, paper, lumber or other commodity ANSWER BC Hydro is expected to meet the standard for the industry in the operation of its facilities and since the Seller’s facilities are taking the place of BC Hydro generating facilities, the Seller’s facilities are expected to meet a similar standard. No, actually Section 6.5 only prohibits Planned Outages in Winter Months, unless BC Hydro consents, and requires that Sellers make reasonable efforts to coordinate Planned Outages with BC Hydro. It also allows BC Hydro to require Sellers to reschedule Planned Outages if the rescheduling does not cause a problem for the Seller. As BC Hydro is contracting for firm power and counting on this power, this provision is required. In terms of Planned Outages in Winter Months, BC Hydro is a winter peaking utility with peak demand in the middle of winter. Winter Months are when delivery of firm power is most critical. Shutdowns during the winter means that the electricity is of less value to BC Hydro. The primary goal of this CBG Call for Tenders is to acquire firm electricity, which will be available in Winter Months. There are many issues that can arise under the EPA – e.g. in relation to supply in “split bid” situations, where there has been previous supply to a host facility, in Page 13 47 48 Why is BC Hydro concerned about the record keeping by the Seller? Customer Based Generation – November 4, 2002 Workshop Questions & Answers relation to force majeure and economic hardship claims, etc. – where the records of the Seller can be critical to the determination of the issues. Capacity / Eligible Electricity Q & A 49 QUESTION Eligible Electricity as Defined in Appendix 1. The particular sub-clause that is of interest is Appendix 1, (aa) (ii). The specific wording of the clause is: subject to sub-section (iv) and (v) below, if such Metered Electricity is greater than GBL but less than or equal to the Plant Capacity, then Eligible Electricity is the product of A and B, where A is equal to the Metered Electricity minus GBL, and B is equal to the Contracted Capacity divided by the Project Capacity. I cannot understand why this clause cannot be simply written as: subject to (iv) and (v) below, if such Metered Electricity is greater than GBL, is the Metered Electricity minus the GBL. The clause as it now stands seem to indicate that if Contracted Capacity is less than Project Capacity BCH will only purchase a portion of the electricity that is generated above GBL. Attached are some sample calculations. In the sample calculations, the proponent has installed another 30 MW of generation but they have decided to only offer a contracted capacity of 25 MW. The GBL is 20 MW so that at full nameplate capacity the Metered Electricity would be 50 MW. In this scenario if the 30 MW new generation, is only generating 25 MW, BCH will only purchase 20.8 MW. This doesn't appear to make sense because the proponent may deliberately have installed equipment with extra capacity to ensure that he can maintain the Contract Capacity. It would be useful if BCH provided some typical ANSWER This applies to a Split Bid. If the Seller has not invoked Hardship and this is not a voluntary turndown, then by elimination it is an involuntary turndown and the principle of share the pain applies. Each party gets its share of generated electricity. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 14 example calculations of Eligible Electricity, similar to my attached example. 50 Could you provide an example of the situation where the Seller does not contract all of the capacity to BC Hydro? Please refer to the November 4th CBG Workshop presentation slide 64 – Example No. 3. In this example the Seller has elected a Contracted Capacity of 3 MW of the 5 MW of Project Capacity. The Eligible Electricity under normal operating conditions is calculated as follows. For the situation where the Metered Electricity ‘Mg’ is between 20 and 23.3 MW: Eligible Electricity is Mg – 20. 51 52 53 Is this calculation consistent with the definition of Eligible Electricity in Appendix 1? Do the 80%, 90% and 110% all relate to the Contracted Capacity? Why does BC Hydro require the nameplate ratings of all electrical generators in the Seller’s Plant? What happens if some of the generation is used for internal purposes? What is the relevance of “Deliveries of Eligible Electricity to an Electrical Host to service the Electrical Host’s electricity will be deemed to be deliveries of Eligible Electricity to the Buyer at the POD for the purposes of this EPA”(Subsection 7.7). Why does BCH get custody, control and risk of this electricity? Yes it is. Yes. Even if some of the generation is used for internal purposes, this information is required as it is used for the purposes of the interconnection study as well as the determination of Generator Baseline determination. Please refer to the definition of 'Electrical Host' in Appendix 1. Delivery to the Electrical Host is deemed to be delivered to BC Hydro. The principle is to ensure that the Seller is entitled to be paid for this electricity at this point, and that if anything subsequently happens such that the electricity cannot be delivered through BCH’s system, or BCH otherwise loses the benefit of it, this is at BCH’s risk. 54 Excess Generation Q & A 55 QUESTION Can excess generation installed as a part of this project be bid in a future call? ANSWER Yes, the Seller could respond to a future call with that additional energy, subject to the requirements of that call. Additional options include load displacement, or sale Page 15 Customer Based Generation – November 4, 2002 Workshop Questions & Answers to a third party. 56 If a customer with a load of 100 MW installed a cogeneration plant with a Project Capacity of 50 MW and selected a Contracted Capacity of 40 MW, what would happen to the other 10 MW of generating capacity, does it offset the energy purchased from BC Hydro? Up to 110% of the Contracted Capacity can be sold to BC Hydro under the CBG contract. The remaining energy, if not sold to others, would displace existing load and reduce the energy purchased from BC Hydro under the customer’s Electricity Supply Agreement (rate 1821 ESA). Pricing & Flow Throughs Q & A 57 QUESTION Wouldn’t it be logical for some flow-through items to be in the EPA? For example, if there is a carbon tax or some other thing that would impact fossil fuel certainly that would impact BC Hydro’s fossil fuel generation and that would flow through to the customer. Is there a reason why that shouldn’t be provided in this EPA for the project proponent? Why is the CFT Adjusted Bid Price reduced by the Recall Adjustment Amount when the recall option is exercised? I thought that the CFT Adjusted Bid Price was only for ranking purposes. ANSWER The ceiling price for the program reflects the all-in price of supply including fuel price risk, based on a fixed price structure not a tolling or flow-through structure. We will not be changing the pricing structure for this call so Bidders must evaluate their risk and bid accordingly. 58 The CFT Adjusted Bid Price is also used in the calculation of the monthly and annual LDs, as per Appendix 4 of the EPA. Green & GHGs Q & A 59 QUESTION Are green projects audited annually to see if the project meets the green criteria? If indeed the project goes from green to not green, at that point on would you lose $5.00/MWh from your payment price? ANSWER As outlined in Appendix 11 of the EPA, internal audits are required every three years. Please also note however, that BC Hydro has a right to come in and audit the facility. Yes, subsequent to cure provisions in the EPA, if the project could not meet commitments regarding the green criteria, the payment price would be adjusted accordingly from expiry of the cure period on. Page 16 60 Customer Based Generation – November 4, 2002 Workshop Questions & Answers 61 It’s my understanding that Ecologo is moving to a prorated approach, so if a facility was 80% green and used 20% fossil fuels they would still deem that to be a green project. Are you likely to adopt that philosophy? The current composite green criteria reflect the current market standards for green. If they are changed, we will evaluate the impacts of those changes on our criteria and decide on appropriate actions at that time. BC Hydro has been tracking the progress of the Ecologo standard carefully over the past two years. We will evaluate a possible migration once the guideline has been finalized and after the release of the BC Energy Policy. CBG proponents that are eligible to be green can elect to allocate those rights to BC Hydro and then the bid price will be adjusted accordingly and if they are awarded an EPA, the green rights will belong to BC Hydro. Under the CBG call, projects that are eligible to be green can also elect not to allocate those rights to BC Hydro and the bid prices will in turn not receive a green adjustment. $3.00/MWh works out to $8.333 per tonne of CO2. 8.333 is derived from the GHG intensity of a combined cycle gas turbine which is 0.36 tonnes/MWh. 3.00/0.36 = 8.333. The $3.00/MWh was a value that BC Hydro attributed to this, taking into consideration the current state of GHG policy in the country. 62 Unlike the green RFP, is it correct that the green rights will remain the property of the seller for the CBG call? 63 On slide 92 it says that green house gas intensity adjustment is $3.00 – 8.333 times the project GHG intensity. Where did the $3.00 and the 8.333 come from? 64 Biomass projects, the slide 87 shows you can use less In both cases, we said 1-3% is what a project typically uses if it meets the green than or up to 3% fossil fuel. In the call for tender criteria. 3% is the working upper limit. documents, you’ve given a range of 1-3, am I correct in assuming that three is the upper limit? So even though Ecologo have set the upper limit at 1.65 Hydro have specified 3%? What is the difference between “Off-Site Emission Reduction Rights” and “Green Rights”? Why do Offsite Emission Reduction Rights belong to BC Hydro? For clarification, the range is presented as up to 3%. While it may be possible that Ecologo states 2% on their Web site, the composite criteria being applied by BC Hydro for the CBG CFT has an upper limit of 3%. Off-Site Emission Reduction Rights and Green Rights are as defined in Appendix 1. Generally speaking, Off-Site Emission Reduction Rights refer to emission reductions specifically, while Green Rights have a broader definition. Off-site emission reductions could occur at BC Hydro facilities if the BC Hydro facility is displaced or “turned down” as a result of green energy supply. BC Hydro is responsible for all environmental liabilities associated with its facilities and entitled to all environmental benefits associated with its facilities. Page 17 65 66 67 Customer Based Generation – November 4, 2002 Workshop Questions & Answers 68 Why does BC Hydro get the reversionary right as per “To the extent that Emission Reduction Rights cannot be lawfully allocated between those arising at the Seller’s Plant and those arising elsewhere or between the Buyer and other purchasers or users of the Electricity, all Emission Reduction rights will be wholly the property of the buyer”? Why is Article 7.10(b) included especially with the right to injunctive relief? The principle at work here is that BC Hydro’s willingness to contract green energy at a premium price entitles it to all environmental benefits associated with that green energy. 69 Article 7.10 (b) is included to ensure that BC Hydro has established an appropriate chain of custody with respect to Off-Site Emission Reduction Rights for the purposes of green power certificates sales commitments and/or compliance with future emissions regulation. BC Hydro would likely look at a number of means to ensure that the chain of custody with Off-Site Emission Reduction Rights exists, one of them being the right to injunctive relief. 70 Under Article 7.12(e) why does the Seller have to comply with all of the requirements of the Certification Agency if selling Green Rights to BC Hydro? This may be more than what the Seller was willing to offer to a third party. As the market for green energy evolves, it is anticipated that “certification” of green power will be a necessary requirement for green power sales. BC Hydro has included Article 7.12(e) in anticipation of this requirement in green power market development, but recognising as well that currently there is no one set of standards or certification body to define green power. BC Hydro would expect that compliance with the Certification Agency’s requirements would be reflected in the Seller’s terms in the Sale Notice for the Offered Green Rights and would be considered by BC Hydro in determining whether to acquire the Offered Green Rights. 71 Under Article 7.12(f) BC Hydro gets more than one opportunity to acquire the Green Rights. Why is that? BC Hydro has more than one opportunity to acquire the Offered Green Rights, subject to the conditions in Article 7.12, to reflect the fact that market conditions and opportunities pertaining to Green Rights develop over time. CPI Q & A 72 QUESTION Which price index is used for the purposes of indexing ANSWER CPI is used and it is defined in Appendix 1 (s) as follows: CPI means the Page 18 Customer Based Generation – November 4, 2002 Workshop Questions & Answers the price following COD? 73 If the change in the CPI was negative in a particular year, would the adjustment to the energy price also be negative for that particular year? Consumer Price Index for Canada, All items (Not Seasonally Adjusted), as published by Statistics Canada. Due to the formula in Section 3.2, Appendix 3 of the EPA, if the change in the CPI in a given year is negative, there will not be a change to the energy price in that year; the price will be the same as in the previous year. Hydrology Adjustment Q & A 74 QUESTION On the hydrology adjustment, could you do an example? I mean the one extreme is you generate for 12 hours and then you switch off for 12 hours. Is that a flat $3.50 price that’s added? ANSWER The adjustment if a flat $3.50/MWh for bid comparison purposes. However, projects that elect the hydrology adjustment are only relieved of the obligation to deliver in the additional circumstances of hydrology limitation. They are still subject to the obligation to deliver. Process Q & A 75 QUESTION Did you give any thought to an alternative to the sealed bid method of pricing such as an auction of some form, where there’s a little more interactive knowledge between the people who are doing the bidding? The sealed bid method is a one-shot lottery style from the proponent’s point of view. Whereas, in an auction you can look around and see how the acceptances are coming in and do some adjustments based on that. BC Hydro requires full corporate approvals at the time the Tender is submitted. This means that millions of dollars must be spent on permits and engineering before the project is selected by BC Hydro. Why not make the bids non-binding with an opportunity for expeditious confirmation of a commitment to the bid price subsequent to its acceptance? ANSWER We opted for the sealed bid concept as being the fairest for everyone concerned. An auction would be more difficult to administer because of the differences from one project to another - for example differences in the adjustments that might be necessary - area location, system, bulk location, green, GHG intensity and hydrology. Some of the information supplied by the bidder is confidential, so it would further complicate using an open auction approach to the bidding. 76 In the interests of fairness and transparency, and commercial certainty, BC Hydro elected to proceed with a tender process under this program. Permitting conditional bids such as has been suggested could turn the process effectively into an option to contract process in favour of the bidder, leaving BC Hydro and others whose bids had initially been rejected in a state of uncertainty and undermining the objective of a fair and transparent process. Page 19 Customer Based Generation – November 4, 2002 Workshop Questions & Answers Code of Conduct Q & A 77 QUESTION What does the Code of Conduct have to do with anything? ANSWER The Code of Conduct has been mandated by BC Hydro’s Board of Directors and is a standard part of all BC Hydro Calls for Tender. It is one of the ways in which BC Hydro ensures that the process is fair and open, and that the persons with whom BC Hydro contracts observe certain minimum ethical standards in their business dealings. BCIAC (arbitration) Process Q & A 78 QUESTION The BCICAC process is expensive and with no time limits. Why not eliminate it? ANSWER Despite delays and costs that the arbitration process can sometimes involve, BC Hydro is of the view that much greater potential for delays and costs exists in court proceedings. In addition, in cases involving specialized technical subject matters, the arbitration processes and the ability to select arbitrators having expertise in the particular subject, can greatly enhance the speedy resolution of disputes. Public Announcements Q & A 79 QUESTION Public announcements on the project are not BC Hydro’s business. Why does BC Hydro have this provision? ANSWER Section 20.9 of the EPA, which is applicable to both parties, is intended to avoid inaccurate or misleading announcements that could be of legitimate concern to the other party. A general “reasonableness” standard applies. Customer Based Generation – November 4, 2002 Workshop Questions & Answers Page 20